Review on enhanced oil recovery by nanofluids

Li, Kewen; Wang, Dan; Jiang, Shanshan

doi:10.2516/ogst/2018025

Cited by 66 publications

(29 citation statements)

References 71 publications

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“…With the pressure drop decreasing to 8.5 MPa, the results suggested that Al-NPs are adsorbed onto the pore surface wall during EOR, which was also reported by Li et al 37 On the other hand, upon flushing the sandstone with a highly saline water (CW 3 and CW 5 ), it is likely that heteroaggregation of Al-NPs is the primary reason for the pressure drop response. As Al-NF travels within the core, SDBS is gradually decreased by adsorption onto the rock surface.…”

Section: Resultssupporting

confidence: 76%

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

et al. 2020

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Injecting nanofluids (NFs) has been proven to be a potential method to enhance oil recovery. Stranded oil is produced by wettability alteration where nanoparticles form a wedge film on pore wall surfaces, which is thought to shrink the pore space of the reservoir. Furthermore, ensuring the stability of the injected NF during the application is a major challenge. A low permeability reservoir and salinity of water make the response of NF injection to the formation damage more difficult. This article, therefore, studied the formation damage induced by the injection of alumina nanofluids (Al-NFs) in a relatively low permeability (7.1 mD) sandstone core. The salinity of the postflush water was also considered to mitigate the destructive impact. Al-NF was formulated by dispersing alumina nanoparticles (Al-NPs) in an aqueous solution of sodium dodecylbenzene sulfonate (SDBS) at its critical micelle concentration (CMC, 0.1 wt %). The formation damage, inherent to Al-NF injection, was evaluated by core-flooding tests. The assays consisted of the injection of 1 PV Al-NF (0.05 wt %) at the trail of which postflush at different salinities was flooded. The study found that the salinity of the postflush has an effect on the formation damage and oil recovery factor (RF). A chase water with a salinity concentration of 3 wt % sodium chloride (NaCl) produced an RF of 8.7% compared to a base case of water-flooding with a pressure drop of up to 13 MPa across the core (70 mm in length). These results pertained to the deposition of Al-NPs at the injection end. However, lowering the postflush salinity to 1 wt % NaCl mitigated the formation damage as evidenced by the decrease in pressure (35%) and an increase in RF to 17.2%.

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Section: Resultssupporting

confidence: 76%

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

et al. 2020

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“…There is a vast amount of literature on the experimental investigation of NPs for EOR methods [6,[21][22][23][24]. Haroun et al compared the injection of smart water and nanofluids.…”

Section: Ph Of Solutionmentioning

confidence: 99%

A Complete experimental study of oil/water interfacial properties in the presence of TiO₂ nanoparticles and different ions

Khalilnezhad

Rezvani

Ganji

et al. 2019

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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Previous studies on Nanoparticles (NPs) application for Enhanced Oil Recovery (EOR) methods have revealed their effective role in the rock wettability alteration, relative Interfacial Tension (IFT) and oil viscosity reduction, formation and stabilization of the emulsions, and reduced asphaltene precipitation, which are all in direct relationship with oil/water interfacial properties. This study focuses on the interfacial properties of oil/water in the presence of Titania NPs and different ions at different pressures and temperatures. For this, different concentrations of TiO2 NPs in the Formation Water (FW) were prepared to monitor the effects of NPs on the oil/water IFT, carbonate rock wettability, zeta potential, and asphaltene adsorption. The results on IFT values indicated that NPs behavior at high pressures and temperatures is completely different, as compared to the ambient conditions, and 1000 ppm NPs introduced the lowest IFT at 600 psi and 60 °C. This reduction is potentially attributed to the asphaltene adsorption at the oil/water interface by TiO2 NPs, which hinders the asphaltene deposition at the interface and in turn IFT increasing. Contact angle results revealed two distinctive behaviors for NPs at high and low concentrations. In other words, with the first interval (below the optimum concentration), an increase in NPs concentration led to a quick wettability alteration toward the water-wet condition, and with the second one (above the optimum concentration), there was an increase in contact angle with an increase in NPs concentration, which is due to the NPs stacking near the rock surface. These results were in good accordance with zeta potential measurements, in which 1000 ppm nanofluid presented the highest stability (zeta potential value of −46.9 mV). Batch adsorption experiments resulted that catalytic TiO2 NPs are capable of adsorbing asphaltene at the oil/water interface. In addition, the results on fitting experimental data to the Langmuir and Freundlich Isotherms showed that the adsorption best fitted Langmuir Isotherm and hence the adsorption type is a monolayer.

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“…On the other hand, surfactants and nanofluids could synergistically decrease oil/water interfacial tension, which helps improve oil recovery [ 12 , 26 , 27 ]. Some research has indicated that nanofluids and surfactants could synergistically increase structural disjoining pressure [ 28 , 29 ]. However, whether surfactants and nanofluids have a synergistic effect on wettability alteration was unknown and is the focus of this study.…”

Section: Resultsmentioning

confidence: 99%

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

Hou

Sun

2021

Nanomaterials

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In recent years, unconventional oils have shown a huge potential for exploitation. Abundant reserves of carbonate asphalt rocks with a high oil content have been found; however, heavy oil and carbonate minerals have a high interaction force, which makes oil-solid separation difficult when using traditional methods. Although previous studies have used nanofluids or surfactant alone to enhance oil recovery, the minerals were sandstones. For carbonate asphalt rocks, there is little research on the synergistic effect of nanofluids and surfactants on heavy oil recovery by hot-water-based extraction. In this study, we used nanofluids and surfactants to enhance oil recovery from carbonate asphalt rocks synergistically based on the HWBE process. In order to explore the synergistic mechanism, the alterations of wettability due to the use of nanofluids and surfactants were studied. Nanofluids alone could render the oil-wet calcite surface hydrophilic, and the resulting increase in hydrophilicity of calcite surfaces treated with different nanofluids followed the order of SiO2 > MgO > TiO2 > ZrO2 > γ-Al2O3. The concentration, salinity, and temperature of nanofluids influenced the oil-wet calcite wettability, and for SiO2 nanofluids, the optimal nanofluid concentration was 0.2 wt%; the optimal salinity was 3 wt%; and the contact angle decreased as the temperature increased. Furthermore, the use of surfactants alone made the oil-wet calcite surface more hydrophilic, according to the following order: sophorolipid (45.9°) > CTAB (49°) > rhamnolipid (53.4°) > TX-100 (58.4°) > SDS (67.5°). The elemental analysis along with AFM and SEM characterization showed that nanoparticles were adsorbed onto the mineral surface, resulting in greater hydrophilicity of the oil-wet calcite surface, and the roughness was related to the wettability. Surfactant molecules could aid in the release of heavy oil from the calcite surface, which exposes the uncovered calcite surface to its surroundings; additionally, some surfactants adsorbed onto the oil-wet calcite surface, and the combined role made the oil-wet calcite surface hydrophilic. In conclusion, the study showed that hybrid nanofluids showed a better effect on wettability alteration, and the use of nanofluids and surfactants together resulted in synergistic alteration of oil-wet calcite surface wettability.

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Review on enhanced oil recovery by nanofluids

Cited by 66 publications

References 71 publications

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

A Complete experimental study of oil/water interfacial properties in the presence of TiO₂ nanoparticles and different ions

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

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Review on enhanced oil recovery by nanofluids

Cited by 66 publications

References 71 publications

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

Formation Damage Induced by Water-Based Alumina Nanofluids during Enhanced Oil Recovery: Influence of Postflush Salinity

A Complete experimental study of oil/water interfacial properties in the presence of TiO2 nanoparticles and different ions

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

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A Complete experimental study of oil/water interfacial properties in the presence of TiO₂ nanoparticles and different ions